1. Field of the Invention
This invention relates to well testing; and more particularly, to a method for determining the concentration of oil-phase fluid in an earth formation.
2. Description of the Prior Art
The importance of determining residual oil in place by means of subsurface logging techniques has been recognized for some time. At the present, new oil fields are becoming more difficult to discover and more attention is being given to secondary and tertiary methods of oil recovery in oil fields. In uncased intervals of a well extending into an oil formation, the oil content can be determined from resistivity logs if the resistivity of a salt-containing formation water within the surrounding formation is known and is of sufficient contrast in resistivity to the oil. It is understood that other parameters such as porosity and lithology must also be known. However, resistivity logs cannot distinguish between oil and fresh water, and it is impossible to obtain resistivity logs in cased wells. Most of oil fields that are being considered for secondary and tertiary recovery have only cased wells, since the field has already been produced by primary methods. The cost of drilling new wells for the sole purpose of running logs in uncased boreholes would in all probability render further recovery processes uneconomical.
The term "indigenous formation fluid" refers to the fluid in subterranean porous rock at the time investigation of a formation is initiated. In a virgin formation, it is a natural mixture of water-phase and oil-phase fluid or the presence of a water-phase fluid and an oil-phase fluid. In a formation that has been waterflooded, it is the fluids remaining in the formation at the end of the flooding operation. The oil-phase fluid may be oil, gas, or a mixture of oil and gas.
Conventional formation evaluation techniques are subject to large uncertainties in region of high water saturation. At 25 percent residual gas or oil saturation, the minimum probable error is about .+-.8 saturation percent, and at 10 percent residual saturation the probable error is about .+-.10 saturation percent.
Evaluations of gas-bearing intervals in open, or uncased, boreholes are subject to additional uncertainties due to gas solubility in filtrate water flowing into a water-receptive formation from a borehole. The decrease in residual gas saturation is proportional to filtration losses since, for most sandstones, the filtrate becomes gas saturated quite quickly. As an example of the magnitude of these effects, only 7 pore volumes of gas-free water is required to reduce residual gas by 10 saturation percent for assumed reservoir conditions of 3,000 p.s.i. and 160.degree.F. (dry gas). Under these conditions, the short spaced resistivity and porosity devices would be affected to some degree even if low water loss muds are used. Pressure coring, used successively in residual oil applications, is subject to error due to gas solubility effects during filtrate flushing.
In copending application to Richardson et al., Ser. No. 633,963 filed Apr. 26, 1967, a method for determining residual oil in a formation that has been reduced to residual oil by water drive or waterflooding is disclosed. This method measures the thermal neutron decay first with the formation water and then with water having a materially different capture cross section substituted for the formation water at least within the radius of investigation of the logging tools. However, as discussed hereinabove, such a technique can be unsuitable for residual gas saturation determination because of the requirement for injection of large quantities of water. Due to problems associated with the solubility of natural gas, it would appear that a cased hole technique in order to determine residual gas saturation accurately is desirable. Also, the technique disclosed in the copending Richardson et al. application requires an independent measure of porosity and is not as accurate as desired.